4Thermochemical Conversion ofCoal and Biomass

This chapter reviews the thermochemical conversion of coal, biomass, and combined coal and biomass to liquid transportation fuels. It addresses the questions raised in the statement of task related to the application of thermochemical conversion to the production of alternative liquid transportation fuels from those feedstocks by discussing the following:

The development status of each major technology with estimated times of commercial deployment.

Challenges and needs in research and development (R&D), including basic-research needs for the long term.

The available technologies are described first, and their status and technical and commercial readiness are assessed. Detailed cost and performance analysis, R&D and demonstration needs, environmental impacts, and analysis of greenhouse gas life-cycle emissions of the key technologies are discussed.

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4 Thermochemical Conversion of
Coal and Biomass
T
his chapter reviews the thermochemical conversion of coal, biomass, and
combined coal and biomass to liquid transportation fuels. It addresses the
questions raised in the statement of task related to the application of ther-
mochemical conversion to the production of alternative liquid transportation fuels
from those feedstocks by discussing the following:
•
The development status of each major technology with estimated times
of commercial deployment.
•
Projected costs, performance, environmental impact, and barriers to
deployment by 2020.
•
Potential supply capability, plant carbon dioxide (CO2) emissions, and
life-cycle greenhouse gas emissions.
•
Challenges and needs in research and development (R&D), including
basic-research needs for the long term.
The available technologies are described first, and their status and technical
and commercial readiness are assessed. Detailed cost and performance analysis,
R&D and demonstration needs, environmental impacts, and analysis of green-
house gas life-cycle emissions of the key technologies are discussed.

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Liquid Transportation Fuels from Coal and Biomass
STATUS AND CHALLENGES OF TECHNOLOGY ALTERNATIVES
Thermochemical conversion involves either the gasification of biomass or coal fol-
lowed by synthesis to liquid fuels (indirect liquefaction) or the direct conversion
of coal to liquid fuels (direct liquefaction) with high-pressure hydrogen (H2), as
shown in Figure 4.1. Those thermochemical conversion processes are considered
to be ready for deployment between now and 2020. Because of its chemical com-
plexity, biomass can also be converted to liquid fuels by pyrolysis or liquefaction.
Those routes are not as well developed.
For each of the technologies, the panel has considered the technological read-
iness, costs, environmental impacts, characteristics of the finished products, and
barriers to deployment. The panel also projected the potential commercial contri-
bution that thermochemical conversion could make in the period 2020–2035 and
beyond 2035.
THERMOCHEMICAL CONVERSION
Indirect Liquefaction Direct Liquefaction
FEEDSTOCK Coal
Coal, Biomass, or Coal and Biomass
Coal Slurry Preparation
Processing, Drying
Preheating
Gasification
H2 Liquefaction
SYNGAS
Solids / Liquids Separation
Fischer-Tropsch (FT) Methanol Synthesis
Raw Liquid Upgrading
Upgrading Methanol to Gasoline MTG
GASOLINE
GASOLINE GASOLINE DIESEL
DIESEL LPG JET FUEL
JET FUEL
FIGURE 4.1 Summary of thermochemical conversion processes discussed in this chapter.
ALTF 4-1

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Thermochemical Conversion of Coal and Biomass
Gasification Options
Processes that break the carbon-containing material down into gaseous products
by gasification and then use those to produce liquid fuels are referred to as indi-
rect processes to distinguish them from “direct” processes that break coal down
into liquid products without going through gaseous intermediates.
For the indirect route of principal interest, solid feedstock is gasified by
reacting it with sufficient oxygen to increase its temperature to a point where
steam can react with the remaining carbonaceous material to produce syngas, a
mixture of carbon monoxide (CO) and H2. Next, the syngas is cleaned to remove
contaminants—such as particles, sulfur, ammonia, and mercury—and further
processed to adjust the ratio of H2 to CO by using the water–gas shift reaction.
The clean syngas is then used to make either a single product, such as fertilizer or
methanol, or multiple products, such as fuels, H2, steam, and electric power.
Gasification has been used commercially around the world for nearly a cen-
tury by the chemical, refining, and fertilizer industries and for more than 35 years
by the electric-power industry. More than 420 gasifiers are in use in some 140
facilities worldwide, including 19 plants in the United States. Gasification tech-
nologies can also be used on the vast Canadian oil-sand deposits to gasify coke
or bitumen to produce H2 and to produce a substitute natural gas from America’s
abundant coal resources (Furimsky, 1998). The gasification process can convert
combined feedstocks, such as coal and biomass, in the same gasifier at the same
time. Thermochemical conversion would use nonfood biomass feedstocks—such
as lignin, cellulose, and plastic wastes—and thus would not raise issues of compe-
tition between the markets for fuel and food.
Synthesis Options
Broadly speaking, two technologies for converting synthesis gas to liquid transpor-
tation fuels have been proved on a commercial scale:
•
Fischer-Tropsch (FT) technology. This technology was developed in
Germany in the 1920s, and commercial plants constructed there in
the middle 1930s were later used to produce transportation fuel in
World War II. FT technology was commercialized in the South African
Synthetic Oil Corporation (Sasol) complexes beginning in the middle
1950s. The process involves the catalytic conversion of the H2 and CO
in synthesis gas into fuel-range hydrocarbons, such as diesel or gaso-

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Liquid Transportation Fuels from Coal and Biomass
line, and naphtha and liquid petroleum gas (LPG). Sasol now produces
transportation fuels from coal at the rate of more than 165,000 bbl/d.
•
Technologies based on methanol synthesis. Synthesis gas can also be
converted to methanol with available commercial technology. The
methanol can be used directly or can be upgraded into high-octane
gasoline with a proprietary catalytic process developed by ExxonMobil
and referred to as the methanol-to-gasoline (MTG) process. Methanol
can also be converted to a mixture of gasoline and diesel with a variant
of the MTG process called the methanol-to-olefins, gasoline, and diesel
(MOGD) process.1 Methanol synthesis can also be the starting point for
producing dimethyl ether (DME) and a broad array of other chemicals.
Direct-Liquefaction Technology
Direct liquefaction of coal involves a selective depolymerization of coal by breaking
apart the coal structure into smaller units. The depolymerization is typically accom-
plished by thermal degradation of the coal with high temperatures and by simulta-
neous addition of hydrogen under high pressure. The hydrogen can be added from
the gas phase or through hydrogen donation from suitable solvents in the presence
of a catalyst. The direct-liquefaction procedures are carried out at about 450°C and
at high pressures up to 30 megapascals (MPa). The product is a synthetic crude
oil that can be refined into liquid transportation fuels. Commercial-scale direct
liquefaction started in Germany in 1926; by 1939, production had reached more
than 1 million tons a year. A commercial-scale plant was started up in the United
Kingdom in 1935. In the 1970s, pilot plants were constructed in Japan and in the
United States after the oil embargo. All those plants have been dismantled because
of the collapse in world oil prices in the early 1980s.
Although direct liquefaction of coal has been demonstrated and is being
scaled up in China, it is not ready for commercial deployment. Many questions
associated with the design and operation of a direct coal-liquefaction plant require
resolution. Most of the unresolved issues require process demonstration operations
and then commercial demonstration. That would require a closely coupled R&D
program to resolve issues and advance the technology. The panel does not deem
1Some would place the option of methanol to olefins, gasoline, and diesel (MOGD) on the list
of synthesis options. Because of the lack of data and operating experience with that option, only
the Fischer-Tropsch and MTG processes are described in this section.

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Thermochemical Conversion of Coal and Biomass
the technology ready for commercial deployment and estimates that an aggressive
process and commercial demonstration program could make it ready for commer-
cial deployment if it shows an advantage for commercial potential relative to other
options for conversion of coal to clean transportation fuels.
Carbon Capture and Storage
During the conversion of coal and biomass to liquid fuels via direct or indirect
liquefaction, large quantities of CO2 are produced. To minimize emission to the
atmosphere, the CO2 must be captured and stored. CO2 from the off-gas streams
of the conversion processes can be readily captured with commercially avail-
able technologies. Permanent geologic storage of the large quantities of CO2 that
would be produced by a full-scale liquefaction industry appears feasible but has
been demonstrated at only a few locations worldwide. Although carbon capture
and storage are discussed in the context of the technical overview of indirect lique-
faction in this chapter, the issues of feasibility and commercial readiness apply to
both direct and indirect liquefaction of coal.
INDIRECT-LIQUEFACTION TECHNOLOGIES
This section describes the overall indirect-liquefaction process that converts coal,
biomass, or coal–biomass mixtures into liquid transportation fuels (Figure 4.2).
Key elements of this process are gasification, syngas cleanup and conditioning,
synthesis, and product upgrading. The process economics and greenhouse gas
emissions of different options of indirect liquefaction are compared in a model
analysis later in this chapter. The technical challenges and product characteristics
are also discussed.
Process Technical Overview
Gasification involves creating a contact between a carbon-containing feed material
and oxygen (or air) and steam at high temperatures to produce synthesis gas. The
several basic gasifier designs are distinguished by the use of wet or dry feed, the
use of air or oxygen, and the reactor’s flow direction (upflow, downflow, or circu-
lating). Today’s pressurized entrained-flow coal gasifiers—such as those developed
by General Electric, Conoco Phillips, Siemens, and Shell—can process feedstock at
about 3000 tons/day. Biomass gasifiers have not generally been used to produce

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Liquid Transportation Fuels from Coal and Biomass
To CO2 Compression
H2
CO2 Injection Gas
Coal Biomass
Sulfur H2
Fuel Gas
Recovery
Feedstock Biomass Gasification COS Sulfur
Selexol
Processing ARG
Quench Hyd Polish
Coal
& Drying
Hg
Removal
Oxygen
Shift
Slag FT
Steam
Air ASU Synthesis
Net Power Plant Power
Product
Recovery/
ST Boiler
Upgrading
Air
BFW
CW Diesel
Make-up
System
Water Naphtha/
Stack Gas Gasoline
FIGURE 4.2 Schematic of generic plant for indirect conversion of coal and/or biomass.
Source: Tomlinson and Gray, 2007.
ALTF 4-2
synthesis gas. They are generally smaller and operate at lower pressures and tem-
peratures than do coal gasifiers. Although there are many fixed-bed biomass gas-
ifiers, fluid-bed and recirculating-bed systems have been developed.
A 3000 tons/day coal gasifier would produce enough synthesis gas to yield
transportation fuel at about 6000 bbl/d by indirect liquefaction. After being
ground into very small particles, the coal can be slurried with water or fed dry
into the gasifier with a controlled amount of air or oxygen and steam. Tempera-
tures in a gasifier range from 1400°F to 2800°F. At such high temperatures in
the gasifier, steam reacts with the carbonaceous material of the feedstock to form
syngas.
Coal Gasification
A number of technologies have been developed for coal gasification; they include
moving-bed, fluid-bed, circulating-bed (transport), and entrained-flow gasifiers
(MIT, 2007). The operating temperature and the size of coal feed vary with the
type of gasifier. The moving-bed gasifier was developed by Lurgi and improved
by Sasol. It operates at 425–600°C and accepts coal feed sizes of 6–50 mm. The

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Thermochemical Conversion of Coal and Biomass
Sasol–Lurgi gasifier has been used extensively at the Sasol commercial plant in
South Africa. Entrained-flow gasifiers operate at 1250–1600°C and accept coal-
feed particles smaller than 100 μm. Those oxygen-blown, high-pressure gasifiers
have been developed by General Electric (it was formerly referred to as the Texaco
gasifier), Shell, Conoco Phillips (E-Gas), and Siemens (formerly referred to as the
Future Energy gasifier). Fluid-bed gasifiers are less developed than the other two
types. They operate at 900–1050°C and can use coal feed of 6–10 mm. In most
types of gasifiers, avoiding soft ash particles is essential because the particles stick
together, stick to process equipment, and typically lead to shutdown (MIT, 2007).
Coal gasification is commercially deployable today by using any one of
several gasification systems that are being commercially used. Producing coal-
to-liquid (CTL) fuels and other applications of gasification will lead to further
improvements in the technology so that it would become more robust and effi-
cient by 2020. Those improvements are part of the usual evolution of any new
technology.
Coal and Biomass Gasification
Adding sustainably grown and harvested biomass to the coal feedstock would
allow an increase in domestic fuel supply while reducing total greenhouse gas
emissions in two ways. First, the emission of carbon in the burning of the fuels
made from biomass is countered by the removal of carbon from the atmosphere
by the biomass through photosynthesis during its growth. Second, the biomass
and coal carbon that is converted to CO2 during the conversion to transportation
fuels could be captured and stored.
The notion of gasifying mixtures of coal and biomass to produce liquid fuels
is relatively new, and there has been little commercial experience. Many gasifiers
can gasify biomass, but most of them are small in scale, use air instead of oxygen,
and operate at lower temperatures and at low or atmospheric pressure. Under
those less severe conditions, pyrolysis dominates, and the main products, in addi-
tion to syngas, are light hydrocarbons, bio-oils, tars, and char. Those products
make such gasifiers less suitable for producing FT liquid fuels.
The NUON Shell 253-megawatt electric (253-MWe) integrated gasification
combined-cycle (IGCC) facility in the Netherlands has proved that gasification
of combined wood (30 percent by weight) and coal can be achieved for the gen-
eration of electric power. It has also gasified other biomass feedstocks, including
chicken litter.

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0 Liquid Transportation Fuels from Coal and Biomass
The operation of a combined coal-and-biomass-to-liquids (CBTL) plant
would be similar to that of a CTL plant, except that biomass is gasified in addi-
tion to coal (Figure 4.2). Separate gasifiers could be used for the biomass and the
coal, but it might be more efficient and cost-effective if the same gasifier could
convert both feeds simultaneously. That would be similar to the situation at the
NUON discussed above in which the Shell gasifier was able to gasify both wood
and other biomass with the same lock-hopper high-pressure feeding system.
Combined coal and biomass gasification is deployable today, although the
amount of biomass relative to coal feed is small, as discussed above. Further com-
mercial development of the technology will make it more robust and efficient and
enhance its ability to use higher fractions of biomass by 2020.
Biomass Gasification
Published data on high-pressure biomass gasifiers are sparse. Because of the
fibrous nature of most biomass sources, the material is difficult to pretreat and
feed into a high-pressure gasifier. Typical problems include clumping and bridging.
Biomass gasification exhibits many similarities to coal gasification, including
the variety of gasifier types and different available approaches to gasification tech-
nology. However, the reaction conditions are generally milder than those for coal
gasification because of the higher reactivity of biomass.
Gasification with direct firing with oxygen at higher pressures and tempera-
tures produces a relatively pure syngas stream with small quantities of CO2 and
other gases. For temperatures greater than 1000°C, little or no methane, higher
hydrocarbons, or tar is present.
A major difference between biomass gasification and coal gasification is that
the former generally involves smaller units than the latter because of the limits on
the availability of biomass in a reasonable harvesting area. Biomass gasification
therefore will not have the benefit of economies of scale that larger-scale coal gas-
ification has. The lack of economies of scale will increase the cost per unit product
of biomass gasification unless major process simplification and capital-cost reduc-
tion can be achieved. Like coal gasifiers, biomass gasifiers can be lumped into spe-
cific types, each of which has many variations.
Several U.S. and European organizations are developing advanced biomass
gasification technologies, and about 10 biomass gasifiers have a capacity greater
than 100 tons/day operating in the United States, Europe, and Japan (IEA, 2007;
Cobb, 2007). Those units have a broad variety of feedstocks, feed capabilities,

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Thermochemical Conversion of Coal and Biomass
characteristics, product-gas cleanup approaches, and primary products. The Bio-
mass Technology Group lists more than 90 installations (most are small) and
more than 60 suppliers of equipment that is used in gasification (Knoef, 2005).
Although several of the available technologies have been commercially demon-
strated, they have yet to be fully demonstrated commercially for integrated bio-
mass gasification and transportation-fuel production. The panel considers biomass
gasification to be technically ready for aggressive commercial demonstration but
not yet well enough understood to ensure efficient, effective commercial deploy-
ment today. Many variations require understanding and improvement. With an
aggressive commercial development program, biomass gasification technology
could be ready for full-scale commercial deployment by 2015. The major issues
to be resolved are related to engineering, particularly the extent of biomass pre-
treatment necessary and effective feeding of biomass to high-pressure gasification
reactors. An example of the conversion of biomass into liquid transportation fuels
is the partnership of Choren Industries and Shell. Choren provides the Carbo V
gasification process, and Shell provides the FT synthesis technology.
Most of the gasification technologies present technical or operational chal-
lenges, most of which can probably be resolved or managed with commercial
experience. Gasifier choice depends on the type of biomass feed and on the spe-
cific application of the gasification or pyrolysis products. The gasifier units will
generally be smaller than large-scale coal gasifiers because of the economics and
logistics of the feed supply. The most persistent problem appears to be related to
biomass feeding, processing, and handling, particularly if a gasifier has to contend
with different biomass feeds.
Syngas Cleanup and Conditioning
The raw syngas produced in the gasification of coal and biomass contains many
impurities, such as CO2, hydrogen sulfide, carbonyl sulfide, ammonia, chlorine,
mercury, and other toxic chemicals. Biomass has much lower sulfur content than
coal does, and sulfur impurities in the syngas are correspondingly lower. However,
biomass ash can contain high concentrations of sodium, potassium, and silicon
that might pose additional requirements for the cleanup system. The impurities
have to be removed before the syngas is allowed to contact the synthesis catalysts;
otherwise, catalyst poisoning and deactivation will result. For example, in the
conceptual configuration shown in Figure 4.2, carbonyl sulfide is hydrolyzed to
hydrogen sulfide. Ammonia is scrubbed out and mercury is removed with acti-

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vated carbon, and CO2 and hydrogen sulfide are removed with Selexol or another
acid-gas removal system. The processes for removing the contaminants are all
commercially available.
In addition to cleaning, the H2:CO ratio is adjusted to be compatible with
the synthesis process by using the water–gas shift process. In this process, CO is
converted by reaction with steam to H2 and CO2. The CO2 can then be removed
in the acid–gas removal system to produce a concentrated stream of CO2 that is
suitable for storage. The same is true for biochemical conversion of biomass to
ethanol. The fermentation step produces a stream of pure CO2 that can be com-
pressed and geologically stored. The transport and storage costs will be somewhat
higher because the amount of CO2 will typically be smaller for the biochemical
conversion route than for a thermochemical conversion route with an equal bio-
mass feed rate. Because synthesis catalysts are readily poisoned by minute quanti-
ties of sulfur, a polishing reactor that removes sulfur down to parts per billion
is included before the synthesis reactor. Ultimately, the hydrogen and carbonyl
sulfides are converted (99.99 percent) to elemental sulfur, and the mercury is
removed.
Syngas cleanup and conditioning technology is ready for full-scale commer-
cial deployment today. It will undergo substantial improvement as a result of nor-
mal process evolution and become more robust and efficient by 2020.
Synthesis
Once the syngas produced by gasification of the carbonaceous feed has been
cleaned of impurities and shifted to the desired H2:CO ratio, it can be used to
synthesize liquid transportation fuels. Two major commercial synthesis processes
can be used to produce transportation fuels, such as gasoline, diesel, and jet fuel.
These are FT and methanol synthesis followed by MTG. DME can also be pro-
duced by dehydration of methanol, but it is not a liquid fuel under ambient condi-
tions. DME is discussed in Chapter 9.
Fischer-Tropsch Synthesis
The clean synthesis gas is sent to FT reactors, where most of the clean gas is con-
verted into zero-sulfur liquid hydrocarbon fuels. If the major required product is
distillate or diesel boiling-range fractions, slurry-phase reactors are used. One of
the limitations of FT synthesis is that it produces a wide array of hydrocarbon
products in addition to some oxygenates. The array of products depends on the

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probability of chain growth relative to chain termination. The probability func-
tion can theoretically be modeled with the Schultz–Flory–Anderson relationship,
in which the parameter alpha determines the shape of the probability curve; the
higher the alpha, the longer the hydrocarbon chains. To maximize liquid products
in the naphtha and diesel boiling range, it is best to produce waxes first and then
to crack the wax selectively to lower-boiling-point materials.
The low-temperature FT process produces about 10 percent hydrocarbon
gases, 25 percent liquid naphtha, 22 percent distillate, and 46 percent wax and
heavy oil. The wax can then be selectively hydrocracked into distillate. With this
approach, the overall product distribution can be skewed in favor of diesel. The
clean fuels are recovered, and the wax is hydrocracked into more diesel fuel and
naphtha. The naphtha can be upgraded into gasoline, but substantial refining
is necessary to produce high-octane material because of the paraffinic nature of
naphtha. The CO2 in the FT tail gas is removed for storage, and the remaining
synthesis gas is returned to the FT reactors for additional liquid production.
The FT process has been used for decades by Sasol and involves reacting syn-
thesis gas over metal-based catalysts to yield a variety of hydrocarbons that can be
converted to high-quality transportation fuels (gasoline, diesel, and jet fuel). The
first such plant, known as Sasol I, used a combination of fixed-bed and circulat-
ing-fluid-bed FT reactors to produce the fuels. Recently, the Sasol I plant changed
from coal to natural gas as feedstock, and it is now a gas-to-liquid (GTL) plant. In
the early 1980s, Sasol built two large FT-based indirect coal-liquefaction facilities
that together produce transportation fuels at over 160,000 bbl/d. The plants were
designated Sasol II and III. Twenty years later, the plants are profitable, but they
received government subsidies for several years after start-up. They would not
have been economically viable in a market economy with relatively cheap oil and
without government assistance.
FT synthesis is continuously being improved; since the building of the large
Sasol plants, there have been substantial advances both in coal-gasification tech-
nologies that produce synthesis gas and in FT technology that produces clean
fuels. The Sasol II and III plants originally used circulating-fluid-bed synthol reac-
tors, which were later replaced by fixed-fluid-bed Sasol advanced synthol reactors.
These are less expensive, are easier to operate, and have a much greater fuel-
production capacity than synthol reactors. Research and development (R&D) at
Sasol started experimenting with slurry-phase FT reactors in the early 1980s and
built a 2,500-bbl/d prototype reactor at Sasol I to demonstrate and develop the
technology. These reactors, which have operated on both iron and cobalt FT cata-

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of loan guarantees, incentive programs to offset capital and operations and main-
tenance costs, or guaranteed purchases of products to get the industry started. A
government–private sector partnership might be necessary for the setup of the first
few direct- or indirect-liquefaction plants.
Environmental Impact
Because coal’s hydrogen:carbon ratio is lower than that of petroleum, transpor-
tation fuels produced from direct liquefaction of coal would have much higher
greenhouse gas emissions than gasoline has. If nonfossil sources of energy were
used for hydrogen production and process heat for the conversion processes, the
net effect of coal-based fuels would be about the same as that of fuels from petro-
leum (NRC, 1990). As discussed earlier, using biomass–coal mixtures in indirect-
liquefaction plants could result in substantial reductions in greenhouse gas life-
cycle emission. That strategy has not been tested for direct liquefaction but should
be investigated for potentially comparable reductions of greenhouse gas emissions.
“The conversion of coal into synthetic fuels can embrace practically any
potential form of pollution and health hazard which can be associated with coal,
including combustion products and ash, phenolic liquors and coal liquids which
are exceptionally rich in known or suspected carcinogens” (Grainger and Gibson,
1981).
Data on water use, especially in the last few years, seem to be sparse. One
estimate suggests water consumption of about 200 million gallons per year for
operation of a plant with a coal capacity of 2000 tons/day (Comolli et al., 1993).
The estimate of about 2 gal of water per gallon of product is consistent with
water needs for indirect liquefaction.
Product Characteristics
Finished products from direct liquefaction are intended to be fully fungible with
respect to comparable petroleum products, but that has not been adequately dem-
onstrated. Direct liquefaction produces low-cetane fuel (cetane index, about 45)
(Mzinyati, 2007). As a replacement for fuel oils, coal liquids are considered to be
more difficult to store, to have higher concentrations of potential carcinogens, to
produce higher quantities of nitrogen oxides, and to have a greater soot-forming
tendency. Blends of coal products with petroleum might form precipitates. Produc-
tion of lighter transportation fuels appears to be accompanied by high rates of
catalyst deactivation and to require high hydrogen consumption.

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FINDINGS AND RECOMMENDATIONS
Gasoline and diesel can be produced from the abundant U.S. coal reserves to have
greenhouse gas life-cycle emissions similar to or less than those of petroleum-based
fuels in 2020 or sooner if existing thermochemical technology is combined with
geologic storage of CO2. Widespread deployment of such facilities will require
major increases in coal mining and transportation infrastructure either for moving
coal to the plants or moving fuel from the plants to the market.
Finding 4.1
Despite the vast coal resource in the United States, it is not a forgone conclusion
that adequate coal will be mined and be available to meet the needs of a growing
coal-to-fuels industry and the needs of the power industry.
Recommendation 4.1
The U.S. coal industry, the U.S. Environmental Protection Agency, the U.S.
Department of Energy, and the U.S. Department of Transportation should assess
the potential for a rapid expansion of the U.S. coal-supply industry and delineate
the critical barriers to growth, environmental effects, and their effects on coal
cost. The analysis should include several scenarios, one of which assumes that the
United States will move rapidly toward increasing use of coal-based liquid fuels
for transportation to improve energy security. An improved understanding of the
immediate and long-term environmental effects of increased mining, transporta-
tion, and use of coal would be an important goal of the analysis.
Geologic storage of CO2, however, would have to be demonstrated at com-
mercial scale and implemented by then. Without CCS, the greenhouse gas life-
cycle emission will be more than twice those from petroleum-based fuels. Coal
can be combined with biomass at a ratio of 60:40 (on an energy basis) to pro-
duce liquid fuels that have greenhouse gas emissions comparable with those from
petroleum-based fuels if CCS is not implemented. With CCS, fuels produced from
coal and biomass would have a slightly negative to roughly zero carbon balance.
Cellulosic dry biomass also can be converted thermochemically to synthetic gaso-
line and diesel without coal. The greenhouse gas life-cycle emissions from those
fuels should be close to zero without CCS and highly negative with CCS, but the

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cost of fuel products will be higher than the cost of those produced from coal or
combined coal and biomass.
Finding 4.2
Technologies for the indirect liquefaction of coal to transportation fuels are com-
mercially deployable today; but without geologic storage of the CO2 produced in
the conversion, greenhouse gas life-cycle emissions will be about twice those of
petroleum-based fuels. With geologic storage of CO2, CTL transportation fuels
could have greenhouse gas life-cycle emissions equivalent to those of equivalent
petroleum-derived fuels.
Finding 4.3
Indirect liquefaction of combined coal and biomass to transportation fuels is close
to being commercially deployable today. Coal can be combined with biomass at
a ratio of 60:40 (on an energy basis) to produce liquid fuels that have greenhouse
gas life-cycle emissions comparable with those of petroleum-based fuels if CCS is
not implemented. With CCS, production of fuels from coal and biomass would
have a carbon balance of about zero to slightly negative.
Finding 4.4
Geologic storage of CO2 on a commercial scale is critical for producing liquid
transportation fuels from coal without a large adverse greenhouse gas impact.
This is similar to the situation for producing power from coal.
Recommendation 4.2
The federal government should continue to partner with industry and independent
researchers in an aggressive program to determine the operational procedures,
monitoring, safety, and effectiveness of commercial-scale technology for geologic
storage of CO2. Three to five commercial-scale demonstrations (each with about
1 million tonnes of CO2 per year and operated for several years) should be set up
within the next 3–5 years in areas of several geologic types.
The demonstrations should focus on site choice, permitting, monitoring,
operation, closure, and legal procedures needed to support the broad-scale appli-

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cation of geologic storage of CO2. The development of needed engineering data
and determination of the full costs of geologic storage of CO2—including engi-
neering, monitoring, and other costs on the basis of data developed from continu-
ing demonstration projects—should have high priority.
The configuration of the thermochemical conversion plants produces a con-
centrated stream of CO2 that must be removed before the fuel-synthesis step, even
in noncapture designs. Thus, the requirement for geologic storage has only a small
effect on cost and efficiency. On a plant basis, the engineering cost of CO2 avoided
is about $10–15/tonne, but the cost is based on a “bottom-up” engineering esti-
mate of expenses for drying, compression, transport, land purchase, drilling wells
and injecting CO2, monitoring, and capping wells. Experience with a variety of
energy technologies suggests that the full cost of geologic storage cannot be cap-
tured by such an approach, because some implementation barriers increase costs
and are difficult to quantify in advance. Accordingly, the numerical geologic cost
used in this report, which is based on factors quantified by an engineering analy-
sis, and life-cycle costs for fuels that entail carbon storage may constitute a lower
bound on future costs.
Finding 4.5
There do not appear to be any technical issues that cannot be resolved or any cost
showstoppers associated with geologic storage of CO2. There is, however, much
to be developed in siting, permitting, monitoring, and site closure; it is essential
that public and political uncertainty be resolved and that costs be better defined.
Uncertainty among the general public and policy makers about the efficacy and
regulatory environment has the potential to raise storage cost. Ultimately, the
requirements for siting, design, operation, monitoring, carbon-accounting proce-
dures, liability, and the associated regulatory frameworks need to be developed
to avoid unanticipated delays in initiating demonstration projects and, later, in
permitting and licensing of individual commercial-scale projects. Extensive experi-
ence with storage in deep saline aquifers has yet to be gained and evaluated. A full
assessment of the future cost of CCS should emphasize, at least qualitatively, the
uncertainty arising from such factors.

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Recommendation 4.3
The government-sponsored geologic CO2 storage projects need to address issues
related to the concerns of the general public and policy makers about geologic
CO2 storage through rigorous scientific and policy analyses. As the work on
geologic storage progresses, any factors that might result in public concerns and
uncertainty in the regulatory environment should be evaluated and built into the
project decision-making process because they could raise storage cost and slow
projects.
The key technologies required to convert coal and cofed coal and biomass
to liquid transportation fuels have been commercially demonstrated and are ready
for commercial deployment. With geologic storage of CO2, coal can be used to
produce liquid transportation fuels that have greenhouse gas life-cycle emission
that is equivalent to that of petroleum-derived fuels. Cofed biomass and coal can
be used to produce liquid transportation fuels that are equivalent to those pro-
duced from petroleum with respect to greenhouse gas life-cycle emission without
geologic storage of CO2 and fuels that have lower greenhouse gas life-cycle emis-
sion with geologic CO2 storage. Technology for producing liquid transportation
fuels with biomass only (BTL) has been demonstrated but requires additional
development to be ready for commercial deployment. It can produce carbon-neu-
tral fuels; with geologic CO2 storage, liquid transportation fuels so produced can
have negative greenhouse gas life-cycle emission. Carbon storage in soils by the
biomass crops can enhance the favorable effect of biomass conversion to fuels but
is hard to project because it depends on many situational and agricultural factors.
Liquid transportation fuels produced from biomass alone would be more expen-
sive than CTL fuels because of the high cost of biomass and the diseconomies of
scale for plants that are small because of limited regional biomass availability.
Using both coal and biomass (CBTL) allows larger plants that can benefit from
economies of scale, that have lower capital costs and use cheaper coal, and that
therefore have lower production costs.
Finding 4.6
The advanced technologies for gasification, syngas cleanup, and Fischer-Tropsch
synthesis have been demonstrated on a commercial scale. Their integration on the
scale required to have a substantial impact on fuel production has not been dem-

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Thermochemical Conversion of Coal and Biomass
onstrated but is not considered a major issue. For first-mover projects to produce
liquid transportation fuels from coal on the scale of a large plant poses a degree of
technical risk; in addition, the risk of price and cost volatility that energy markets
have shown recently has to be considered. The risk greatly increases the difficulty
of developing and funding first-mover projects.
Finding 4.7
Technologies for the indirect liquefaction of coal to produce liquid transportation
fuels with greenhouse gas life-cycle emissions equivalent to those of petroleum-
based fuels can be commercially deployed before 2020 only if several first-mover
plants are started up soon and if the safety and long-term viability of geologic
storage of CO2 is demonstrated in the next 5-6 years.
Recommendation 4.4
A program of aggressive support for first-mover commercial plants that produce
coal-to-liquid transportation fuels and coal-and-biomass-to-liquid transportation
fuels with integrated geologic storage of CO2 should be undertaken immediately
to address U.S. energy security and to provide fuels with greenhouse gas emissions
similar to or less than those of petroleum-based fuels. The demonstration and
deployment of “first-mover” coal or coal-and-biomass plants should be encour-
aged on the basis of the primary technologies, including CCS to demonstrate the
technological viability of CTL and CBTL fuels and to reduce the technical and
investment risks associated with funding of future plants. If decisions to proceed
with commercial demonstrations are made soon so that the plants could start up
in 4–5 years and if CCS is demonstrated to be safe and viable, those technologies
would be commercially deployable by 2020.
Recommendation 4.5
The first-mover coal or coal–biomass plants recommended above should be sited
so that they provide CO2 for several of the sponsored geologic CO2-storage proj-
ects, and their progress should be expedited to facilitate the geologic CO2-storage
projects and the further development of conversion technologies. To the extent
possible, the conversion plants and geologic storage should be implemented as a
package. As a first step, a few CTL plants and CBTL plants could serve as sources

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0 Liquid Transportation Fuels from Coal and Biomass
of CO2 for a small number of CCS demonstration projects. However, so-called
capture-ready plants that vent CO2 would create liquid fuels with higher CO2
emissions per unit of usable energy than those from petroleum-based fuels; their
commercialization should not be encouraged before commercially available CCS is
proved to be safe and sustainable.
Finding 4.8
The technology for producing liquid transportation fuels from biomass or from
combined biomass and coal via thermochemical conversion has been demonstrated
but requires additional development to be ready for commercial deployment.
Recommendation 4.6
Key technologies should be demonstrated for biomass gasification on an inter-
mediate scale, alone and in combination with coal, to obtain the engineering and
operating data required to design commercial-scale synthesis gas-production units.
Finding 4.9
Conversion plants that use 60 percent coal and 40 percent biomass as feedstock
can be configured to eliminate recycling of unconverted synthesis gas and thereby
generate a substantial amount of additional electric power. If the CO2 captured
from such a plant is stored geologically, both the liquid transportation fuels and
the electric power produced for sale to the grid could have zero greenhouse gas
life-cycle emissions. That approach might present a key opportunity to address
emissions from both transportation and power.
Recommendation 4.7
A thorough systems analysis should be developed for process configurations of
coal-and-biomass-to-liquids plants that eliminate recycling of unconverted synthe-
sis gas and generate substantial additional electric power. The plants’ fuel cost and
power costs, potential to address greenhouse gas emissions, and potential impact
on U.S. oil consumption should be assessed thoroughly.